For the first 100 years and more of oil exploration and production, wells were drilled almost exclusively in geologic formations that permitted production of oil and gas flowing under the natural pressures associated with the formations. Such production required that two physical properties of the geologic formation fall within certain boundaries. The porosity of the formation had to be sufficient to allow a substantial reserve of hydrocarbons to occupy the interstices of the formation, and the permeability of the formation had to be sufficiently high that the hydrocarbons could move from a region of high pressure to a region of lower pressure, such as when hydrocarbons are extracted from a formation. Typical geologic formations having such properties include sandstones.
In recent years, it has become apparent that large reserves of hydrocarbons are to be found in shale formations. Shale formations are typically not highly permeable, and therefore present formidable obstacles to production. The most common technique in use today that permits economic production of hydrocarbons, and especially natural gas from shale formations, is hydraulic fracturing (often referred to as “fracking”). This technique can be also be applied to older wells drilled through non-shale formations to increase the proportion of hydrocarbons that can be extracted from them, thus prolonging well life.
Fracking involves pumping fluid under very high pressure into hydrocarbon-bearing rock formations to force open cracks and fissures and allow the hydrocarbons residing therein to flow more freely. Usually the fluids injected into such formations contain chemicals to improve flow, and also contain “proppants” (an industry term for substances such as sand). When the fracturing fluid is removed, and the hydrocarbons are allowed to flow, the sand grains prop open the fractures and prevent their collapse, which might otherwise quickly stop or reduce the flow of hydrocarbons.
Drilling technology has evolved to allow wells to be drilled along virtually any direction or azimuth, and is no longer constrained to the drilling of vertical wells only. Deviated wells are thus often drilled along specific geologic formations to increase production potential. The extent of a hydrocarbon-producing formation in a vertical well may be measured in feet, or perhaps tens or hundreds of feet in highly productive areas. The maximum area of the formation in contact with the vertical well bore is quickly computed as the circumference of the well multiplied by the height of the producing formation. In practice, the producing area is much less than this figure. By drilling horizontally or non-vertically through a formation, the extent of the formation in contact with the wellbore can be much greater than is possible with vertically-drilled wells. Injecting deviated wells with hydraulic fracturing fluid can result in the propagation of fractures outwardly from the wellbore, and thereby increase significantly the total volume of the subsurface from which the hydrocarbons can be extracted.
The progress of a fracturing operation must be monitored carefully. Well fracturing is expensive, and the fracturing process is frequently halted once its benefits become marginal. The high pressures associated with fracturing result in fractures that tend to follow existing faults and fractures, and can result in an uneven or unpredictable fracture zone. Fracturing fluid may also begin following an existing fault or fracture zone and then propagate beyond the intended fracture zone. Care must also be taken not to interfere with existing production wells in the area. For these and other reasons, it is important that the fracturing operator be permitted to follow accurately the progress of the fluid front in the subsurface while the fluid is being injected into the well.
Conventional surface seismic reflection surveys generally do not work well for monitoring the movement or positions of fluid fronts in the subsurface. The physical dimensions of fractures are often shorter than can be detected using conventional surface seismic reflection techniques. In addition, within a given formation there may be no or low contrasts in seismic velocity, and as a result surface seismic reflection techniques cannot be used effectively to image fractures within the formation. Fractures also tend to scatter seismic energy, further obscuring their detection by conventional surface seismic reflection means.
An alternative approach to the problem of imaging factures or fluid fronts within formations known as “microseismicity” has its origins in earthquake seismology and in technology developed to monitor nuclear tests. Instead of using “active” surface seismic energy sources, “passive seismic” techniques are used to detect seismic energy generated in the subsurface of the earth. Seismic energy emitted by fracturing a geologic formation, which is caused by the injection of high pressure fracturing fluid into the formation, is sensed and recorded. The objective then becomes determining the point of origin of the emitted seismic energy, which defines the location of the fracture.
One method of locating fractures and faults in geologic formations is known as Seismic Emission Tomography (SET). Examples of SET techniques and processes are described in U.S. Pat. No. 6,389,361 to Geiser entitled “Method for 4D permeability analysis of geologic fluid reservoirs” (hereafter “the '361 patent”) and in U.S. Pat. No. 7,127,353 to Geiser entitled “Method and apparatus for imaging permeability pathways of geologic fluid reservoirs using seismic emission tomography” (hereafter “the '353 patent”), the disclosures of which are hereby incorporated by reference herein in their respective entireties.
The SET process entails recording microseismic data using an array of sensors, which are typically located on the surface of the earth. Data are recorded over a given time period, with the duration of recording and the sampling interval being controlled by the objectives of the seismic data acquisition process, the characteristics of the events that generate the detected or sensed seismic energy, the distances involved, the characteristics of the subsurface, and other factors. The data recorded at each sensor location are then filtered and processed using SET processing techniques and software, which convert the data into a series of gridded subsurface volumes corresponding to multiple time samples. The values of the points in the grid represent given attributes of the data, which values vary over time as the energy emitted at each point in the subsurface varies.
What is required for effective monitoring of a fracturing operation is the ability to generate a near-real-time display of a predetermined attribute or characteristic of microseismic data, or a set of predetermined attributes or characteristics of microseismic data, that is capable of indicating the points of origin of microseismic energy in the subsurface, and the growth of a fracture network over time.